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| Start date | Site | Title | Description | System | |
|---|---|---|---|---|---|
| 05000373/FIN-2018412-01 | 30 September 2018 23:59:59 | LaSalle | Licensee-Identified Violation | ||
| 05000373/FIN-2018201-01 | 30 September 2018 23:59:59 | LaSalle | Security | ||
| 05000373/FIN-2018003-08 | 30 September 2018 23:59:59 | LaSalle | Failure to Implement Engineering Change Results in Reactor Coolant Boundary Leakage | The inspectors documented a self-revealed finding of very low safety significance (Green) and associated NCVs of TS 5.4.1 Procedures, and TS 3.4.5 for the failure to implement EC 354539 to perform the final piping weld for the 1B33F067B bonnet vent line in the field, resulting in pressure boundary leakage when the weld failed at power. | |
| 05000374/FIN-2018003-07 | 30 September 2018 23:59:59 | LaSalle | Potential Failure to Promptly Correct the Unit 2 Primary Containment Wall Cavity Leakage Condition and to Follow Corrective Action Program Process | Condition description in AR 2420888 indicated that leakage through the Unit 2 primary containment wall has been a longstanding open issue. The leak was initially identified in 1998 when water leakage was noticed on the external side of the primary containment wall. The leakage was approximately 2025 drops per minute at the primary location and multiple areas near the 180 degree azimuth at construction joints on elevations 813 and 795. Another minor leak was noticed at a similar location near the 0 degrees azimuth. The condition was documented in AR 2269. The source of water leakage was determined to be a weld on a 2 fuel pool cooling drain line and work order 98109950 was initiated to repair the weld. The work was not scheduled and the work order was eventually cancelled. In 2010, the leakage was documented again in AR 1086083. A technical evaluation documented as ATI14709531847 in 2014 concluded that there was no adverse impact on structural adequacy of the containment. The technical evaluation stated that the leakage was to be repaired in the upcoming outage through work order 855785. Action request 2420888 was written in December 2014 to re-enter the condition in the CAP. It recommended corrective actions for liner ultrasound testing every other refueling outage, completion of weld repair, and performance of a technical evaluation for structural impact on the concrete, reinforcing steel, tendons, and liner. The technical evaluation assignment was closed to the evaluation documented under ATI14709531847 discussed above. The corrective action assignment for the weld repair was closed to a work order which has not been completed to-date. Based on the inspectors review, the licensee has deferred the actions to correct this condition identified in 1998. The inspectors question whether the continuous leakage could lead to deterioration of the concrete, corrosion of the reinforcement, or degradation of post tensioned tendons if it enters the tendon sheath or trumpet area; and therefore a condition adverse to quality. This unresolved item remains open pending additional inspector review of the issue with respect to regulatory requirements. Planned Closure Action: Inspectors will seek additional information from the licensee and the NRC will perform internal reviews to evaluate compliance with NRC regulations | Primary containment |
| 05000373/FIN-2018003-06 | 30 September 2018 23:59:59 | LaSalle | Potential Failure to Inspect Containment Post-Tensioned Tendons per Code Requirements and to Follow Corrective Action Program Process | Vertical and horizontal post tensioned tendons, along with reinforcing steel, are required to maintain structural integrity of the primary containment. There are a total of 120 vertical post tensioned tendons along the periphery of the primary containment wall, including 60 Group C tendons and 30 each of Groups A and B. Section 5.5.6 of the Technical Specifications describes the Inservice Inspection (ISI) program for post tensioning tendons and states that the Tendon Surveillance Program shall be in accordance with ASME Section XI, Subsection IWL as required by 10 CFR 50.55a. One Group B tendon (V213B) on Unit 1 was inspected in 1999 and according to the inspection records, water was identified on all components of the tendon. No presence of water is one of the acceptance criteria per Subsection IWL of the ASME Section XI. No condition report was found for this adverse condition. Subsequently, a condition involving degraded vertical tendons was identified during inspections in 2003 and documented in AR 157920. The degradation consisted of broken wires. The Root Cause Report (RCR) for this condition noted that 11 Group A tendons were found degraded and water induced corrosion was the root cause for tendon degradation. The evaluation concluded that five Group A tendons and all 30 Group B tendons in each unit were not susceptible to water intrusion because they were protected by welded covers. These tendons with welded covers were also determined to be inaccessible, and therefore exempt from future inspections requirements in accordance with provisions of ASME Section XI, IWL. The RCR did not address the condition of water found during the Group B tendon inspection in 1999. Additionally, to verify this assumption of welded covers providing protection from water intrusion, a corrective action was generated to inspect one Group A and one Group B inaccessible tendons during the next outage. Pertaining to inaccessible tendons, the inspectors noted the following requirements of 10 CFR 50.55a(b)(2)(viii)(E): Concrete containment examinations: Fifth provision. For Class CC applications, the applicant or licensee must evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or the result in degradation to such inaccessible areas. For each inaccessible area identified, the applicant or licensee must provide the following in the ISI Summary Report required by IWA6000: (1) A description of the type and estimated extent of degradation, and the conditions that led to the degradation; (2) An evaluation of each area, and the result of the evaluation; and (3) A description of necessary corrective actions. After the licensee identified degraded group A tendon locations, to comply with the provision of 10 CFR 50.55a, the licensee documented in its 90 day post outage ISI reports information on the degraded A tendons in 2004 and 2005 for units 1 and 2, respectively. This information included an assumption that the extent of degradation did not apply to the Group B tendon locations because of a welded cover at locations that precluded entry of water. Additionally, a corrective action, CA 15792033, was generated to inspect one Group A and one Group B tendon during the next refueling outage to verify this assumption. The corrective action was closed without inspection of any Group B tendon based on a management decision following satisfactory inspection of a Group A tendon in 2006. The licensees decision failed to take into account the fact that the most recent inspection of a Group B tendon showed presence of water on tendon components and also that the welded closure details were different for tendons in the two groups. Subsequently, the licensee identified a concern regarding inadequate closure of this corrective action during its reviews for the license renewal application in 2014. Specifically, the licensee wrote AR 1658189 to document that due to the differences in the welded cover designs, the results of the Group A tendon inspection may not be applicable to Group B tendons. Therefore the critical assumption regarding the adequacy of Group B tendon covers remained unverified. In particular, the Group B tendon cover used dissimilar metal welds and water was found inside the cover during the most recent inspection. The licensee identified actions to perform inspections on two of the Group B tendons on each unit in addition to inspecting the tendon V213B where water was initially found. These actions were categorized as action tracking items (ACITs), items that do not represent conditions adverse to quality. Since water was found on all tendon components during the last inspection of a Group B tendon, and water induced corrosion was found to be the root cause of many tendon failures, the assumption in the RCR that the welded covers would prevent water intrusion needed to be validated through inspections. This unresolved item remains open pending additional inspector review of the issue with respect to regulatory requirements. Planned Closure Action: Inspectors will seek additional information from the licensee and the NRC will perform internal review to evaluate compliance with NRC regulations. | Primary containment |
| 05000373/FIN-2018003-05 | 30 September 2018 23:59:59 | LaSalle | Failure to Translate Fuel Oil Relief Valve Setting into Design Drawing of Record. | The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees failure to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to accurately translate the Division III EDG fuel oil relief valve set point from the design drawing of record, VPF341110, to the fuel oil pressure operator rounds alert value in the Division III EDG operating procedures. | |
| 05000373/FIN-2018003-04 | 30 September 2018 23:59:59 | LaSalle | Failure to Manage the Increase in Risk During a Battery Charger Capacity Tes | The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(4) for the failure to manage risk when the licensee failed to adhere to procedure WCAA101, Revision 28, On-line Work Control Process. Specifically, procedural requirements regarding a dedicated operator for manual restoration actions and written instructions to credit the availability of the A RHRSW pump during the battery charger testing were not met. | |
| 05000373/FIN-2018003-03 | 30 September 2018 23:59:59 | LaSalle | Failure to Establish Goals to Monitor Steam Tunnel Check Dampers | Introduction: The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50.65(a)(1) for the licensees failure to establish goals to monitor the performance of steam tunnel check dampers. Specifically, the licensees goals for functional failure and condition monitoring could always be satisfied given a two years monitoring period with only one testing opportunity. | |
| 05000373/FIN-2018003-02 | 30 September 2018 23:59:59 | LaSalle | Failure to Establish an Appropriate Inservice Testing Procedure | The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to prescribe procedures that were appropriate to the circumstances, for activities affecting quality, that included appropriate quantitative or qualitative acceptance criteria for determining that important activities had been satisfactorily accomplished. Specifically, the CSCS bypass line isolation valve IST procedure did not contain acceptance criteria to verify the necessary valve obturator movement. | |
| 05000373/FIN-2018003-01 | 30 September 2018 23:59:59 | LaSalle | Failure to Establish Heat Exchanger Inspection Procedures Appropriate for the Circumstances | The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions Procedures, and Drawings, for the licensees failure to ensure that activities affecting quality were prescribed by documented procedures of a type appropriate to the circumstances. Specifically, the licensee failed to ensure that procedure ERAA3401002 appropriately accounted for partially blocked HX tubes identified during HX inspections. | |
| 05000387/FIN-2018011-01 | 30 September 2018 23:59:59 | Susquehanna | Failure to conduct proper testing of 125 VDC molded case circuit breakers to confirm their design adequacy long-term | The inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XI, Test Control. Specifically, Susquehanna has not established a program to adequately exercise and test safety-related 125VDC molded case circuit breakers (MCCBs) since initial plant operation. | |
| 05000410/FIN-2018003-02 | 30 September 2018 23:59:59 | Nine Mile Point | Minor Violation | During the review of Licensee Event Report (LER) 05000220/2017-002-01, Manual Reactor Scram Due to Presesure Oscillations, the inspectors identified a minor violation of 10 CFR 50.9, Completeness and accuracy of information. The LER was found to be inaccurate. Specifically, the LER timeline contained inaccurancies regarding the time operators entered a special operating procedure and did not include an actuation of high-pressure coolant injection (HPCI). The timeline stated at 2:10 AM operators entered the special operating procedure for Pressure Regulator Malfunction, due to reactor pressure oscillations of 2-3 psig. At 2:27 AM operators inserted a manual scram of the reactor due to pressure oscillations exceeding procedural limits. This information was confirmed by a review of the operational logs for March 20, 2017. During OI Investigation 1-2018-002, it was determined that this entry was not accurate and although an exact time could not be established is was estimated to have been at 2:20 AM vice 2:10 AM. Additionally the timeline did not include a mention that at 2:16 AM unexpected turbine trip signal was received and HPCI was initiated due to a tagging error. Operators reset HPCI at 2:18 AM and restored main feedwater flow to restore Reactor Vessel water level. A sixty day telephone notification instead of a written licensee event report was conducted for this invalid initiation of HPCI was completed on May, 11, 2017, as EN 52747 as allowed by 10 CFR 50.73(a)(2)(iv). Screening: Violations involving the submittal of inaccrurate or incomplete information are evaluated under Traditional Enforecement because they impact the NRCs regulatory process. Accordingly, the inspectors evlauted this issue against the example violations in Section 6.9 of the NRC Enforcement Policy. Inspectors concluded that the violation is of minor safety significance because the inaccurate information did not change the NRCs review of the licensee event report. Enforcement: 10 CFR 50.9 requires that information provided to the Commission by a licensee shall be complete and accurate in all material respects. Contrary to the above, on June 22, 2015, Entergy provided information to the Commission that was not complete and accurate in all material respects. In the licensee event report, Exelon documented incorrect information that resulted in the NRC launching a substation further inquiry (OI investigation), but did not substantiate that licensed operators deliberately failed to follow a Technical Specifications required procedure. Exelon identified the inaccuracy and entered the issue into the corrective action program (IR 04091110) on January 7, 2018, and submitted LER 05000220/2017-002-01 on August 18, 2018, revising the timeline to show operators entering N1-SOP-31.2 at 2:20 AM vice 2:10 AM. The disposition of this violation closed Licensee Event Report 05000220/2017-002-01 | Feedwater |
| 05000410/FIN-2018003-01 | 30 September 2018 23:59:59 | Nine Mile Point | Failure to Ensure that Thermal Power is Less Than or Equal to the Licensed Power Limit | The inspectors identified a Green finding and associated non-cited violation (NCV) of the NMPNS Unit 2 Operating License (NPF-69), Condition 2.C(1), Maximum Power Level, when Exelon did not ensure that thermal power was less than or equal to the licensed power limit of 3988 megawatts-thermal (MWth). Specifically, on multiple occurrences between May 22, 2018 and October 19, 2018, licensed operators in the main control room did not appropriately monitor and control 2-hour average thermal power at or below the licensed power limit. The inspectors determined the 2-hour average thermal power exceeded the licensed power limit outside of normal steady-state fluctuations, and did not take timely, effective corrective action to reduce thermal power below the licensed power limit when the 2-hour average was found to exceed the licensed power limit | |
| 05000397/FIN-2018003-01 | 30 September 2018 23:59:59 | Columbia | Failure to Follow Radiologically Controlled Area Procedures | The inspectors reviewed a self-revealed Green, non-cited violation of Technical Specification 5.4.1(a) when the licensee failed to implement radiation control procedures. On June 1, 2017, a supplemental health physics technician (HPT) entered a posted locked high radiation area without a functioning electronic dosimeter (ED). Although the area was posted as a locked high radiation area (LHRA), there were no measured dose rates in excess of 1 rem per hour during this entry. The HPT logged on to Radiation Work Permit (RWP) 30003852 and entered the radiologically controlled area (RCA) to cover a job to add additional shielding in the travelling in-core probe (TIP) Mezzanine room. The HPT entered the RCA through the HP swing gate near the RCA exit point, in order to obtain survey instruments for the job coverage. The HPT proceeded to the dress out area and then to the TIP Mezzanine room, where he entered with a survey meter. After about 10 minutes in the room, the HPT looked at his ED and noticed that it was in pause mode (i.e., not functioning). The HPT informed the worker he was covering, and they both left the LHRA. During the RWP logging process, there was an error when the HPTs ED was being programmed that went unnoticed. As a result, the HPT was signed-on to the RWP, but the ED was not programmed and active. Because the HPT used the HP swing gate at the RCA exit rather than the normal access point with electronic turnstiles that verify ED function, this errant condition was not identified. The swing gate used was intended for HPTs assigned to assist workers with contamination alarms at the RCA exit, not as an RCA entry point to perform work or cover a job. Licensee Procedure GEN-RPP-04, Entry Into, Conduct In, and Exit From Radiologically Controlled Areas, Section 4.13 Dosimetry and Log-in, paragraph (e), requires workers to ensure that electronic dosimetry is on immediately before entering the RCA. The HPT neither used the electronic turnstiles nor checked to see if the ED was on prior to entering the RCA.Additionally, licensee Procedure 11.2.7.3 High Radiation Area, Locked High Radiation Area, and Very High Radiation Area Controls, Section 3.2.4 Coverage and Monitoring of Work, paragraph (d), describes conducting a peer-check prior to LHRA entries, by the job coverage HPT, to verify that workers are wearing an active ED (i.e., not in pause mode) in the appropriate location on the body. The job coverage HPT checked to see that workers had an ED appropriately placed, but did not check the ED setpoints or if the ED was active.Multiple barriers that could have prevented this situation from occurring were either ineffective or not used. Had the error reduction/prevention measures been used, the ED programming error during RWP log on would have been identified.Corrective Action(s): An immediate corrective action, in addition to the HPT being restricted from the RCA, was a stand down conducted with radiation protection personnel about this incident and coaching on use of the procedures related to the verification of dosimetry and peer-checking prior to entry into LHRAs. Corrective Action Reference: AR 00366701 | |
| 05000397/FIN-2018003-02 | 30 September 2018 23:59:59 | Columbia | Failure to Control Workers in a High Radiation Area (>1.0 rem per hour) | The inspectors reviewed a self-revealed Green, non-cited violation of Technical Specification (TS) 5.7.2(b) and (e) when the licensee failed to control worker activities in a locked high radiation area in accordance with the requirements of the RWP and failed to determine radiological conditions in the work area prior to the start of work. | |
| 05000397/FIN-2018003-03 | 30 September 2018 23:59:59 | Columbia | Failure to Adequately Control Work Hours for Covered Personnel | The inspectors identified a Green, non-cited violation of 10 CFR 26.205 associated with the licensees failure to adequately schedule and control work hours for personnel subject to work hour controls. Specifically, the licensee failed to appropriately schedule and control work hours for at least three Chemistry Technicians who were providing covered work as the designated Emergency Response Organization (ERO) Duty Chemistry Technician as defined by the Columbia Generating Station Emergency Plan. | |
| 05000397/FIN-2018003-04 | 30 September 2018 23:59:59 | Columbia | Licensee-Identified Violation | This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy. Title 10 CFR 20.1902(a) requires the licensee to post each radiation area with a conspicuous sign bearing the radiation symbol and the words "CAUTION, RADIATION AREA."Contrary to the above, from November 9, 2017 to November 13, 2017, the licensee failed to post a radiation area with a conspicuous sign bearing the radiation symbol and the words "CAUTION, RADIATION AREA."The licensee moved two resin liners with high dose rates into the turbine building truck bay. Once the resin liners were in the turbine building truck bay, a high radiation area boundary was posted around them. However, the dose rates outside the truck bay doors were not verified. On November 13, 2017, the licensee, while conducting routine area surveys, identified an unposted radiation area outside the turbine building truck bay doors, which resulted from the resin liners inside of the truck bay area. The licensee secured the radiation area and adequately posted it, as required. | |
| 05000352/FIN-2018003-01 | 30 September 2018 23:59:59 | Limerick | Failure to Assess and Manage Risk Associated with Fuel Oil Storage Tank Maintenance | An NRC-identified Green NCV of 10 CFR 50.65(a)(4) was identified when Exelon failed to assess and manage risk associated with fuel oil storage tank maintenance by not properly evaluating and establishing compensatory actions for maintaining availability of associated EDGs | |
| 05000352/FIN-2018003-02 | 30 September 2018 23:59:59 | Limerick | Failure to Correct Adverse Environmental Conditions Impacting Low Pressure Coolant Injection Outboard Primary Containment Isolation Valve | A self-revealed Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI was identified when Exelon failed to correct adverse environmental conditions affecting the Unit 1 LPCI outboard PCIV actuator that resulted in long term water intrusion, corrosion, and failure of the valve to stroke closed. | Primary containment Low Pressure Coolant Injection |
| 05000352/FIN-2018010-01 | 30 September 2018 23:59:59 | Limerick | Minor Violation | During this inspection, the team reviewed the details and status of Exelons corrective actions. Relative to EDG voltage, the TSs specified a lower limit of 4160 Vac; however, Exelons existing analysis determined the lower EDG voltage limit should be 4235 Vac. Exelon determined that this higher voltage value was necessary in order to ensure full EDG operability and qualification when considering a specific criteria (voltage drop during the loading sequence) as per NRC Regulatory Guide 1.9, Application and Testing of Safety-Related Diesel Generators in Nuclear Power Plants. The team determined that there was not an operability concern because Exelon determined that, although the voltage drop during the starting of the largest electrical load was slightly below the Regulatory Guide 1.9 value, all required loads would, in fact, successfully start and run as designed when started at the 4160 Vac level. Further, the EDG voltage regulators are designed and calibrated to operate the EDGs at 4235 Vac. Notwithstanding, the team identified that the associated EDG surveillance procedures did not contain the higher, administrative limit of 4235 Vac as an acceptance criterion (4160 Vac was specified). The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the use of non-conservative acceptance criterion was a minor procedure violation because the EDGs were controlled and operated to maintain voltage at 4235 Vac (and 4160 Vac does not render the EDGs inoperable), and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in their corrective action program as IR 4164579 to document and correct this deficiency. For EDG frequency, the TSs allowed an acceptance band (58.8 61.2 Hertz), which is a range typical of EDG transient loading conditions. However, as described in WCAP-17308-NP, and as determined by Exelon engineering staff, a more narrow band (59.9 60.2 Hertz) is the appropriate operating range for steady state EDG operation. Exelon has appropriately maintained the narrow band as the acceptance criteria in the associated EDG surveillance procedures (compensatory action until TSs are revised). However, during this inspection, the team identified that in 2016, Exelon had slightly widened the acceptable band a one-tenth hertz to 59.8 60.2 Hertz. Further review by the team identified that this change was not properly evaluated in accordance with Exelons procedure change process. In particular, the procedure change received a less rigorous review than a 10 CFR 50.59 screen would have provided; and the team concluded that this screen should have been performed. In response, Exelon evaluated past surveillance results and analyzed the lower frequency value of 59.8 Hertz, and determined there to be no adverse consequence at 59.8 Hertz. The team reviewed Exelons analysis and similarly concluded that there was no adverse safety impact. The team reviewed this issue using Inspection Manual Chapter 0612, Appendix B, Issue Screening, and determined that the improper procedure change was a minor procedure violation because there were no adverse consequences and EDG reliability or availability were not adversely affected. Exelon entered this minor violation in there corrective action program as IR 4160819 and IR 4161542 to document and correct this deficiency. | |
| 05000397/FIN-2018002-01 | 30 June 2018 23:59:59 | Columbia | Failure to Maintain Configuration Control in the Diesel Generator 2 Diesel Cooling Water System | The inspectors reviewed a self-revealed, Green, non-cited violation of Technical Specification 5.4.1.a for the licensees failure to perform maintenance in accordance with written procedures appropriate to the circumstances. Specifically, on April 9, 2018, the licensee inadvertently bumped and partially opened a diesel cooling water valve, DCW-V-8B2, while operating a nearby demineralized water valve, DW-V-14B2, as part of work activities under Work Request (WR) 29127677, and rendered diesel generator 2 inoperable and unavailable. | |
| 05000387/FIN-2018002-01 | 30 June 2018 23:59:59 | Susquehanna | Control Structure Chiller Inoperability Due to Identified Refrigerant Leaks Not Corrected | A Green finding and associated non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action was self-revealed when the licensee failed to promptly correct a condition adverse to quality associated with the B control structure chiller which rendered the B control structure chiller inoperable. | |
| 05000387/FIN-2018002-02 | 30 June 2018 23:59:59 | Susquehanna | Inadequate Procedure Adherence to Radiation Protection Requirements | A Green finding and associated NCV of Technical Specification (TS) 5.7, High Radiation Area, was self-revealed when two plant workers entered a posted high radiation area, and one workers electronic dosimeter alarmed on dose rate. The workers had not been briefed for entry into this area. | |
| 05000387/FIN-2018002-03 | 30 June 2018 23:59:59 | Susquehanna | Inadequate Justification for Deferral of Corrective Actions for certain Degraded Safety-Related Components | The inspectors identified a Green finding and associated NCV of TS 5.4.1, Procedures, when the licensee failed to promptly correct numerous operable but nonconforming or degraded safety-related components. | |
| 05000387/FIN-2018002-04 | 30 June 2018 23:59:59 | Susquehanna | EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel (EGM-11-03) | From April 2 through April 24, 2018, Susquehanna performed OPDRVs without establishing secondary containment integrity. An OPDRV is an activity that could result in the draining or siphoning of the reactor pressure vessel water level below the top of fuel, without crediting the use of mitigating measures to terminate the uncovering of fuel. TS 3.6.4.1, Secondary Containment, requires that secondary containment be operable, and is applicable during OPDRVs. The required action for this specification if secondary containment is inoperable in this condition of applicability is to initiate actions to suspend OPDRVs immediately. As reported in LER 05000387/2018-001, Susquehanna conducted the following OPDRVs during the period of secondary containment inoperability: Recirculation system maintenance and pump replacement; Reactor water cleanup system flushes and maintenance; RHR system maintenance; Hydraulic control unit and control rod drive system maintenance; Local power range monitor replacements, including Intermediate Range Monitor 1E Dry Tube replacement; Control rod drive mechanism replacements; and Core spray instrument line flush. NRC EGM 11-03, EGM on Dispositioning BWR Licensee Noncompliance With TS Containment Requirements During Operations With A Potential For Draining The Reactor Vessel, Revision 3, provides, in part, for the exercise of enforcement discretion only if the licensee demonstrates that it has met specific criteria during an OPDRV activity. The inspectors assessed that Susquehanna adequately implemented these criteria. In accordance with EGM 11-003, in order to continue to receive enforcement discretion, a license amendment request (LAR) must be submitted and accepted for review within 12 months of the NRC staffs publication of the generic change, which occurred on December 20, 2016. The inspectors verified that Susquehanna submitted the required LAR on September 20, 2017 (ADAMS Accession No. ML17265A434), and that it was subsequently accepted by the NRC for review by a letter dated October 16, 2017 (ADAMS Accession No. ML17290A024).Corrective Action: Susquehanna submitted an LAR to adopt TS Task Force Traveler 542, Reactor Pressure Vessel Water Inventory Control, on September 20, 2017.Corrective Action Reference: AR-2015-01733 Enforcement: Violation: TS 3.6.4.1, Secondary Containment, requires that secondary containment be operable, and is applicable during OPDRVs. The required action for this specification if secondary containment is inoperable in this condition of applicability is to initiate actions to suspend OPDRVs immediately. Therefore, failing to maintain secondary containment operability during OPDRVs without initiating actions to suspend the operation was considered a condition prohibited by TSs as defined by 10 CFR 50.73(a)(2)(i)(B). Contrary to the above,from April 2 through April 24, 2018, Susquehanna performed OPDRVs without establishing secondary containment integrity. Basis for Discretion: The NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy because all criteria described in EGM 11-003 were met, enforcement discretion was previously authorized by EA-2017-089, and the licensee submitted an LAR on September 20, 2017 which was subsequently accepted by the NRC for review on October 16, 2017, and, therefore, will not issue enforcement action for this violation. The disposition of this violation closes LER 05000387/2018-001-00. | Secondary containment Reactor Pressure Vessel Core Spray Reactor Water Cleanup Intermediate Range Monitor Control Rod |
| 05000220/FIN-2018002-02 | 30 June 2018 23:59:59 | Nine Mile Point | Inadequate Procedure Causes Water Hammer Condition Resulting in Isolation and Inoperability of the 12 Train of the Emergency Condenser System | The inspectors identified a Green finding and associated NCVof 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, when Exelon did not provide appropriate quantitative or qualitative criteria and guidance to operators in procedure N1- OP- 13 Emergency Cooling System to return an emergency condenser loop to service without inducing a water hammer condition which caused operators to re-isolate the emergency condenser loop and declare it inoperable | |
| 05000410/FIN-2018002-01 | 30 June 2018 23:59:59 | Nine Mile Point | Failure to Ensure Proper Control of the Standby Gas Treatment System Damper Valve, 2GTS*V2000B, Within Procedures, Materials, and Design Control Measures | The inspectors identified a Green finding and associated NCVof 10 CFRPart 50, Appendix B, Criterion III, Design Control, when Exelon failed to ensure proper control of the SGTS damper valve 2GTS*V2000B within procedures, materials, and design control measures. Specifically, on April 15, 2018 operators attempted to run B SGTS for containment purge; however, no flow was observed and the system was secured. Operators discovered the 2GTS*V2000B closed due to the failure of the operating mechanism to maintain control of the valve position. | Standby Gas Treatment System |
| 05000352/FIN-2018002-01 | 30 June 2018 23:59:59 | Limerick | Failure to Conduct Adequate Radiation Surveys and Evaluate Potential Radiological Hazards | A self-revealing Green finding and associated NCV of 10 CFR 20.1501, Surveys and Monitoring: General, was identified when Exelon failed to perform adequate loose surface contamination surveys of the Unit 1 RWCU isolation valve room prior to authorizing work to hang shadow shielding near the HV-051-1F017A valve, and also during the conduct of the work itself. Exelon also did not identify very high levels of loose surface contamination on overhead piping and structures which surrounded the work area. This failure resulted in unplanned internal radiation exposures to three personnel, including an RPT who was assigned to monitor the radiological aspects of the work. | |
| 05000352/FIN-2018002-02 | 30 June 2018 23:59:59 | Limerick | Unit 1 Core Spray Pump Failed to Start Resulting in Condition Prohibited by Technical Specifications | The inspectors identified a Severity Level IV NCV of Unit 1 Technical Specification 3.5.1 because one core spray subsystem was inoperable from July 17, 2017, until October 5, 2017. Specifically, the Unit 1 C core spray pump did not start upon demand during testing and was declared inoperable because the pumps associated circuit breaker closing charging springs were not charged. | Core Spray |
| 05000373/FIN-2018002-04 | 30 June 2018 23:59:59 | LaSalle | Minor Violation - Follow-up of Events and Notices of Enforcement Discretion | Minor Violation: For S/RV 2B21F013L, serial number N63790050012 (hereafter referred to as S/RV 12), the licensee completed a work group evaluation as documented in AR 03975216ACIT No. 3 to investigate the cause for two S/RVs that failed a set pressure lift test out of specification low. For ACIT No. 3, the licensee staff incorporated a vendor letter that documented the results of the S/RV vendors review of the S/RV 12 condition and which recorded an out of tolerance spring condition. It stated that The spring was measured and rate tested. The free height was found to be below the minimum original equipment manufacturer specified tolerance. The licensees vendor subsequently replaced the nonconforming spring with a new spring. In prior vendor correspondence with the licensee (reference E-mail dated June 24, 2015), the vendor stated that Typically we contribute a low as-found lift to an out-of-tolerance spring rate or free height dimension. Therefore, the nonconforming spring free height dimension may have caused the low as-found lift setpoint failure for this valve and as such was relevant (e.g. material) to the determination of a failure cause that was reported in LER 05000374/201700400 and 01. However, the licensee failed to identify this during their cause investigation and erroneously reported in LER 05000374/201700400 and 01 that The vendor reported for both valves that all the spring tolerances were within the acceptance limits. The licensee documented this violation in AR 04134591, Potential Minor Violation for Unit 2 LER 20170401. The licensee also submitted a revision to the LER as LER 05000374/201700402 Screening: The significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it is necessary to address this violation which could impede the NRCs ability to regulate using traditional enforcement to adequately deter non-compliance. The inspectors determined that this issue was a Severity Level IV violation based on Example 6.9.d.10 in the NRC Enforcement Policy which states, A failure to identify all applicable reporting codes on a Licensee Event Report that may impact the completeness or accuracy of other information (e.g. performance indicator data) submitted to the NRC. In accordance with the Section 2.2.1.c of the NRC enforcement policy, the severity level of a violation involving the failure to make a required report to the NRC will depend on the significance of and the circumstances surrounding the matter that should have been reported. The NRC had not relied on information in this LER report to make a regulatory decision, and the inspector answered no to each of the more than minor screening questions in Appendix B of IMC 0612 for the issue of concern. Therefore, the NRC determined this was a minor violation because it was associated with a minor performance deficiency. Violation: Failure to comply with 10 CFR 50.9 Completeness and accuracy of information and accurately report the nonconforming S/RV 12 spring tolerance in LER 05000374/201700400 and 01 to the NRC constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. | |
| 05000373/FIN-2018002-03 | 30 June 2018 23:59:59 | LaSalle | Licensee-Identified Violation | This violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy. Violation: Technical Specification LCO 3.4.4 (applicable for Modes 1, 2 and 3) states: The safety function of 12 safety relief valves (S/RVs) shall be OPERABLE, and Action Statement A states that One or more required S/RVs inoperableA.1 be in mode 3 in 12 hours and A.2 be in Mode 4 in 36 hours. Technical Specification SR 3.4.4.1 states that Verify the safety function lift setpoints of the required S/RVs are as follows Number of S/RVs Setpoint (psig 2 1205 36. 3 1195 35. 2 1185 35. 4 1175 35. 2 1150 34. Contrary to the above, during portions of previous Unit 1 and 2 operating cycles from 2012 through January of 2017, two main steam S/RVs did not meet these lift pressure setpoint requirements. Specifically S/RV 2B21F013C lifted at 1131 psig instead of from 1139.8 to 1210.2 psig and S/RV 2B21F013L lifted at 1130 psig instead of from 1159.2 to 1230.8 psig (reference: Licensee Event Report 05000374/201700400; 01, Two Main Safety Relief Valves Failed Inservice Lift Inspection Pressure Test. Significance/Severity: This licensee identified finding affected the Initiating Events Cornerstone and was screened in accordance with Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At Power. The two affected SRVs lifted low outside of their setpoint band, which was conservative with respect to maintaining the reactor coolant system overpressure protection safety function of these valves. Therefore, the inspectors determined that this finding is of very low safety significance (Green) because after a reasonable assessment of degradation, the finding would not have resulted in exceeding the reactor coolant system leak rate for a small LOCA and did not affect other systems used to mitigate a loss-of-coolant accident. Corrective Action Reference: AR 3974669 | Reactor Coolant System Safety Relief Valve Main Steam |
| 05000373/FIN-2018010-01 | 30 June 2018 23:59:59 | LaSalle | Failure to Translate Reactor Building Superstructure Design Basis | Inspectors identified a Green finding and associated Non-Cited Violation of Title 10of the Code of Federal Regulations, Part 50, Appendix B, Criterion III, Design Control, for licensees failure to assure that applicable Updated Final Safety Analysis Report described design basis for the Reactor Building (RB) superstructure were correctly translated to field documents was a performance deficiency. Specifically, Updated Final Safety Analysis Report Tables 3.8-9 and 3.8-11 define the design basis load combinations and the corresponding design stress limits applicable to the RB superstructure. Design calculation L-003415 evaluates these load combinations and applies RB overhead crane lifting limitations which ensures these design basis are met. The licensee failed to translate these limitations into specifications, drawings, procedures, or instructions which would ensure the specified stress limits for RB design basis load combinations would not be exceeded while operating the RB overhead crane. | |
| 05000373/FIN-2018002-02 | 30 June 2018 23:59:59 | LaSalle | Failure to Follow Procedure and Perform Database Revision Review Requirements | The inspectors identified a Green finding of very low safety significance for the licensees failure to follow procedure NSWPWM03, Predefine Database Revisions, Revision 0, for retiring procedure LESGM108, Inspection of 480V Motor Control Center Equipment, that performed bus bar inspection on Division 3 motor control centers. Specifically, instead of completing NSWPMW03, step 6.5, Database Revision Review Requirements, to retire the bus bar inspections for Division 3 motor control centers, the licensee retired the procedure based solely on having previously retiring the bus bar inspections for Division 1 and Division 2 in 2002,and did not performthe required review. | |
| 05000373/FIN-2018002-01 | 30 June 2018 23:59:59 | LaSalle | Failure to Implement a Preventative Maintenance Strategy for Residual Heat Removal Service Water Pump Shorting Relays | A self-revealed Green finding of very low safety significance was identified for the licensees failure to implement a preventative maintenance (PM) strategy for the residual heat removal service water (RHRSW) pump shorting relays in accordance with procedure MAAA716210, Performance Centered Maintenance (PCM) Process, Revision 11. Specifically, a PCM template was issued in 2002 that required periodic as-found testing and calibration for control and timing relays, but a maintenance strategy was never implemented. As a result, one of the normally closed contacts on the Unit 1 D RHRSW pump shorting relay developed a high contact resistance and prevented the Unit 1 D RHRSW pump from starting. | Residual Heat Removal Service Water |
| 05000373/FIN-2018001-02 | 31 March 2018 23:59:59 | LaSalle | Failure to Update Throttle Valve Position in Accordance with Station Procedures | The inspectors identified a Green finding of very low safety significance and an associated Non-Cited Violation (NCV) of LaSalle Technical Specifications 5.4.1, Procedures, for the licensees failure to implement station procedures recommended in Regulatory Guide 1.33, Appendix A, Section 9. Specifically, on two separate occasions while performing a flow balance on the Unit 1 A diesel generator (DG) cooling water system, procedural errors resulted in the licensee failing to update the throttle valve position to be used during manual backwash of the Unit 1 A DG cooling water strainer with the correct position. | |
| 05000373/FIN-2018001-01 | 31 March 2018 23:59:59 | LaSalle | Post-Maintenance Testing Failed to Demonstrate Testable Check Valve Function | A self-revealed Green finding of very low safety significance and an associated Non-Cited Violation (NCV) of 10 CFR 50, Appendix B, Criterion XI, Test Control, was documented by the inspectors for the licensees failure to perform post-maintenance testing that would demonstrate that structures, systems and components (SSCs) would perform satisfactorily in service. Specifically, following maintenance on the Unit 2 B residual heat removal (RHR) shutdown cooling (SDC) return testable check valve, 2E12F050B, and the Unit 1 A RHR SDC return testable check valve, 1E12F050A, the post maintenance test performed failed to identify that they would not open fully when in service, resulting in the valves being unable to pass full flow during SDC mode of RHR operation. | Shutdown Cooling Residual Heat Removal |
| 05000352/FIN-2018001-02 | 31 March 2018 23:59:59 | Limerick | Emergency Diesel Generator Combustion Air Overheating | A self-revealed Green NCV of LGS Unit 1 TS 6.8.1 and TS 3.8.1.1 was identified when Exelon failed to properly maintain an operating procedure to maintain a fail-safe design feature for the EDGs which led to the D12 EDG combustion air overheating and caused the EDG to be inoperable for greater than its TS allowed outage time. | Emergency Diesel Generator |
| 05000353/FIN-2018001-01 | 31 March 2018 23:59:59 | Limerick | Failure of Emergency Diesel Generator Lube Oil Pipe Nipple Fitting | A self-revealed Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, and LGS Unit 2 technical specification (TS) 3.8.1.1 was identified when Exelon failed to correct a degraded lube oil pipe nipple fitting on the D22 emergency diesel generator (EDG) when maintenance was performed to address leakage which caused inoperability of the EDG for greater than its TS allowed outage time. | Emergency Diesel Generator |
| 05000387/FIN-2018410-02 | 31 March 2018 23:59:59 | Susquehanna | Security | ||
| 05000387/FIN-2018410-01 | 31 March 2018 23:59:59 | Susquehanna | Security | ||
| 05000387/FIN-2018010-01 | 31 March 2018 23:59:59 | Susquehanna | Licensee-Identified Violation | This violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section2.3.2 of the Enforcement Policy.Violation: 10 CFR 50.49(e)(5) requires, in part, that the electrical equipment qualification program must replace or refurbish the equipment at the end of its designated life.Contrary to the above, on November 16, 2017, the licensee identified that thirteen Unit 1, NAMCO limit switches in environmentally qualified (EQ) applications inside primary containment were not installed in their fully qualified configuration. Specifically, contrary to vendor instructions and EQAR-004 requirements, the limit switches for several containment isolation valves (CIV) have had their covers removed and reinstalled without replacing the gasket and cover screw O-rings. For this application, opening and/or removing the limit switch gasket /and cover screws O-ring constituted the end of the gasket/O-ring designated life. Significance/Severity Level: The inspectors evaluated this finding using IMC 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, Exhibit 3, Barrier Integrity Screening Questions. The inspectors determined that the finding was of very low safety significance (Green), because the limit switches provide only an open or closed signal indication in the main control room, so that operators are aware of the valve position, and can make appropriate assessment of plant conditions. The safety function of the containment isolation valves was not affected. | Primary containment |
| 05000387/FIN-2018001-01 | 31 March 2018 23:59:59 | Susquehanna | Licensee-Identified Violation | This violation of very low safety significant was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a Non-Cited Violation, consistent with Section 2.3.2 of the Enforcement Policy.Violation: Susquehanna Unit 1 TS section 5.4.1 requires that written procedures shall be implemented covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Susquehannas implementing instruction NDAP-QA-0503, General Housekeeping, Transient Material and Internal Cleanliness, Revision 45 implements aspects of the Regulatory Guide administrative procedures requirements. NDAP-QA-0503 section 6.1.5.h requires, in part, that transient equipment shall be located such that it will not impact safety related equipment during a seismic event. Locate all items at a distance greater than the height of the item from safety related equipment. Additionally, TS 3.5.1 Action Statement I directs immediate entry into Limiting Condition for Operation (LCO)3.0.3 if one core spray subsystem is inoperable with one low pressure coolant injection (LPCI) subsystem inoperable. LCO 3.0.3 requires action to be taken within 1 hour to place the unit in MODE 2 within 7 hours and MODE 3 within 13 hours.Contrary to the above, from December 1, 2017 to December 3, 2017, Susquehanna staged a 540 pound, ten foot long replacement pipe on 34 inch high stands within 34 inches of the safety related Unit 1, B Core Spray room cooler. Susquehanna concluded that the room cooler was inoperable because the pipe could have reasonably contacted and damaged the flexible conduit for the power cable to the room cooler during a seismic event. Additionally, from 7:48 a.m. on December 2, 2017 to 1:35 p.m. on December 3, 2017, maintenance was performed on the Unit 1, division 2 LPCI swing bus motor generator which rendered the division 2 LPCI system inoperable. During this time, Susquehanna did not perform the required actions of LCO 3.0.3 and remained in MODE 1.Significance/Severity Level: This violation is of very low safety significance (Green), since this finding did not represent a loss of system, a loss of function of at least a single train for greater than its TS allowed outage time, or a loss of a non-TS train. Corrective Action Reference(s): CR-2017-20227; CR-2018-01717; CR-2018-02250 | Core Spray Low Pressure Coolant Injection |
| 05000373/FIN-2018001-03 | 31 March 2018 23:59:59 | LaSalle | Enforcement Action (EA) 18035: Licensee Implementation of Enforcement Guidance Memorandum 15002, Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance | On June 10, 2015, the NRC issued Regulatory Issue Summary (RIS) 201506, Tornado Missile Protection (ML15020A419), focusing on the requirements regarding tornado-generated missile protection and required compliance with the facility-specific licensing basis. The RIS also provided examples of noncompliance that had been identified through different mechanisms and referenced Enforcement Guidance Memorandum (EGM) 15002, Enforcement Discretion For Tornado Generated Missile Protection Non-Compliance, which was also issued on June 10, 2015 (ML15111A269) and revised on February 7, 2017 (ML16355A286). The EGM applies specifically to an SSC that is determined to be inoperable for tornado generated missile protection. The EGM stated that a bounding risk analysis performed for this issue concluded that tornado missile scenarios do not represent an immediate safety concern because their risk is within the LIC504, Integrated Risk-Informed Decision-Making Process for Emergent Issues, risk acceptance guidelines. The EGM provided for enforcement discretion of up to three years from the original date of issuance of the EGM. The EGM allowed NRC staff to exercise this enforcement discretion only when a licensee implements, prior to the expiration of the time mandated by the LCO, initial compensatory measures that provided additional protection such that the likelihood of tornado missile effects were lessened. In addition, licensees were expected to follow these initial compensatory measures with more comprehensive compensatory measures within approximately 60 days of issue discovery. The comprehensive measures should remain in place until permanent repairs are completed, or until the NRC dispositions the non-compliance in accordance with a method acceptable to the NRC such that discretion is no longer needed. Appendix A to 10 CFR 50, General Design Criteria for Nuclear Power Plants (GDC), Criterion 4, Environmental and Dynamic Effects Design Basis, states in part that SSCs important to safety shall be adequately protected against dynamic effects including missiles. On February 15, 2018, during evaluation of protection for Technical Specifications (TS) equipment from the damaging effects of tornado generated missiles, LaSalle County Station identified a non-conforming condition in the plant design such that specific TS equipment is considered to not be adequately protected from tornado generated missiles. Specifically, tornado generated missiles could strike the components supporting the operation of Control Room (VC) and Auxiliary Electric Room (VE) ventilation. This could result in inoperable VC/VE systems, which provide a protected environment for occupants to control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke if a tornado were to occur. In addition, the Unit 2 Division 2 motor control center (MCC) 236X1 was affected, which impacted various loads on Unit 2 including the Unit 2 standby gas treatment, Unit 2 Division 2 post LOCA system, B main control room area filtration system supply and exhaust fan, reactor building Division 2 isolation damper control logic, Unit 2 Division 2 battery room exhaust fan and Unit 2 24/48 Volt battery rooms exhaust fans. This would result in a loss of power to components and systems rendering them inoperable. The condition was reported to the NRC in Event Notice (EN) 53213 as an unanalyzed condition and potential loss of safety function. Corrective Actions: The licensee documented the inoperability of the SSCs and the affected TS Limiting Conditions for Operation (LCOs) in the CAP and in the control room operating log. The shift manager notified the NRC resident inspector of the implementation of EGM 15002, and documented the implementation of the compensatory measures to establish the SSCs operable but nonconforming prior to expiration of the LCO required action. Initial (immediate) compensatory measures were established by an operations standing order that included: Procedures were verified to be put in place, with associated current training, for performing actions in response to a tornado. Procedures were verified to be put in place, with associated current training, for actions to be taken if a tornado watch is issued for the area. Procedures were verified to be put in place, with associated current training, for actions to be taken if a tornado warning is issued for the area. Verification that training was up to date for individuals responsible for implementing preparation and response procedures; and Established a heightened station awareness and preparedness level relative to identified tornado missile vulnerabilities. The comprehensive (60 day) compensatory measures were established by incorporating the standing order actions and adding additional detail to operating procedure LOATORN001, High Winds/Tornado, Revision 22, for completing additional inspections and restoration actions on equipment vulnerable to tornado missile damage. Corrective Action Program References: AR 4104401; AR 4104391; AR 4104393; AR 4104396; AR 4104397. Enforcement: Violation: The enforcement discretion was applied to the required shutdown actions of the following TS LCOs for both units: TS 3.7.4, Control Room Area Filtration (CRAF) System; TS 3.7.5, Control Room Area Ventilation Air Conditioning (AC); TS 3.6.4.2, Secondary Containment Isolation Valves (SCIVs); TS 3.6.4.3; Standby Gas Treatment (SGT) System; and TS 3.8.7, Distribution SystemsOperating. Severity/Significance: The subject of this enforcement discretion, associated with tornado missile protection deficiencies was determined to be less than red (i.e., high safety significance) based on a generic and bounding risk evaluation performed by the NRC in support of the resolution of tornado-generated missile non-compliances. The bounding risk evaluation is discussed in Enforcement Guidance Memorandum 15002, Revision 1, Enforcement Discretion for Tornado-Generated Missile Protection Non-Compliance, and can be found in ADAMS, Accession No. ML16355A286. Basis for Discretion: The NRC exercised enforcement discretion in accordance with Section 2.3.9 of the Enforcement Policy and EGM 15002 because the licensee initiated initial compensatory measures that provided additional protection such that the likelihood of tornado missile effects were lessened. The licensee implemented actions to track the more comprehensive actions to resolve the nonconforming conditions within the required 60 days. These comprehensive actions were to remain in place until permanent repairs were completed, which for LaSalle were required to be completed by June 10, 2018, or until the NRC dispositioned the non-compliance in accordance with a method acceptable to the NRC such that discretion was no longer needed | Secondary containment |
| 05000410/FIN-2018001-02 | 31 March 2018 23:59:59 | Nine Mile Point | Potential Inadequate 50.59 Evaluation for TS 3.3.1.1 Bases Change | On February 23, 2018, Exelon personnel performed a 50.59 Screening for a change to Unit 2 TS Bases 3.3.1.1, Reactor Protection System (RPS) Instrumentation, for MSIV and TSV surveillance testing. Exelon personnel performed this activity to address operating experience associated with the use of a test box that prevents a scram signal during RPS surveillance testing for TS 3.3.1.1 Function 5 MSIV Closure and Function 8 TSV Closure. TS Bases B 3.3.1.1, C.1, Revision 1 was revised to state, in part, For Function 5 (MSIV Closure), this would require both trip systems to have at least one channel associated with the MSIVs for each main steam line in one Trip Logic Channel (not necessarily the same main steam lines for both trip systems), Operable or in trip (or the associated trip system in trip). For Function 8 (Turbine Stop Valve Closure), this would require both trip systems to have the channels for one Trip Logic Channel, Operable or in trip (or the associated trip system in trip).The inspectors questioned whether the change to TS Bases B 3.3.1.1 resulted in a change to the implementation of TS 3.3.1.1. A licensee is permitted to make changes to their Technical Specification Bases documents without NRC review and approval. However, in certain cases, such as a change to the Technical Specification Bases that would change how the associated Technical Specification is applied, NRC review and approval would be required.Planned Closure Action(s): The inspectors sent written questions to request assistance from NRR to determine whether this change to the TS Bases reasonably would have required NRC review and approval. The inspectors are opening a URI to determine if this is violation of 10 CFR 50.59 and if it is more than minor. Licensee Action: Documented NRCs concern as AR 04055602. Exelons position is the change would not affect how TS 3.3.1.1, or its note, is applied and therefore NRC review was not required.Corrective Action Reference: AR04055602 NRC Tracking Number: 05000410/2018001-02 | Reactor Protection System Main Steam Line |
| 05000220/FIN-2018001-01 | 31 March 2018 23:59:59 | Nine Mile Point | Potential Failure to Submit an 8-Hour Event Notification for a Valid Actuation of HPC | On March 18, 2018,at 1:18 a.m., during the Unit 1maintenance outage while the unit was in cold shutdown, operators received multiple low level alarms on the GEMAC 11 and 12 level indications. Operators responded by adjusting reactor water cleanup reject flow and the feedwater minimum flow control valve to raise reactor water level. Upon the operators making the adjustment to reactor water level, the feedwater low flow control valve was slow to respond, but eventually opened more rapidly, and the increased flow from feedwater resulted in a rapid rise in reactor water level. At 1:28 a.m., indicated reactor water level rose to the 95-inch trip setpoint for the 11 and 12 Yarway level indication instruments, resulting in a turbine trip and HPCI initiation signal. The HPCI pumps were tagged out and thus did not inject, and the turbine was offline for the shutdown. The 11 and 12 Yarway level indication instruments provide reactor protection system logic inputs for reactor vessel water level; however, the Yarway level indication instruments are not density compensated. Therefore, under cold shutdown conditions, actual reactor vessel water level was lower than indicated water level on the 11 and 12 Yarways. During cold shutdown conditions, the GEMAC level instruments, which are calibrated to cold shutdown conditions, provide an accurate indication of actual reactor vessel water level. The GEMAC instruments both indicated well below the trip setpoint of 95 inches (indicated ~72 inches) when the turbine trip and HPCI initiation signal were received. Exelon determined that this event was not reportable under 10 CFR 50.72.Title 10 CFR 50.72(b)(3)(iv)(A) states, Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B) of this section, except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. (B) The systems to which the requirements of paragraph (b)(3)(iv)(A) of this section apply are: 10 (5) BWR reactor core isolation cooling system; isolation condenser system; and feedwater coolant injection system. Planned Closure Action(s): The inspectors requested the 10 CFR 50.72 subject matter experts at the Office of Nuclear Reactor Regulation (NRR) and Office of General Council (OGC) to review whether this was a valid actuation and thus reportable. The inspectors are opening an unresolved item (URI) to determine if a performance deficiency exists.Licensee Action(s): Licensee entered the concern into their corrective action program, and communicated with NRC Region I and NRR Staff. Exelons position is that the event was not reportable. Corrective Action Reference:IR 04116336 NRC Tracking Number: 05000220/2018001-01 | Feedwater Reactor Protection System Reactor Core Isolation Cooling Reactor Water Cleanup |
| 05000397/FIN-2018001-01 | 31 March 2018 23:59:59 | Columbia | Failure to Follow Procedure Leads to Loss of Secondary Containment | The inspectors reviewed a self-revealed, Green, non-cited violation of Technical Specification 5.4.1.a for the licensees failure to perform maintenance in accordance with documented instructions appropriate to the circumstances. Specifically, on September 12, 2017, the failure to verify power sources per Work Order 02072924 caused an electrical transient that caused the reactor building exhaust valve and supply valve to lose power and close, resulting in a loss of secondary containment | Secondary containment |
| 05000397/FIN-2018401-01 | 31 March 2018 23:59:59 | Columbia | Security | ||
| 05000397/FIN-2018401-02 | 31 March 2018 23:59:59 | Columbia | Security | ||
| 05000220/FIN-2017004-05 | 31 December 2017 23:59:59 | Nine Mile Point | Licensee-Identified Violation | The following violation of very low safety significance (Green) was identified by Exelon and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a NCV. Title 10 CFR 50.65(a)(4) requires, in part, ...the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. Exelon procedure WC-AA-101-1006, On-Line Risk Management and Assessment, Revision 001, Section 4.1.3, states to consider work activities that cause equipment to be unavailable (e.g., trains of systems) for assessment of risk under the requirements of 10 CFR 50.65(a)(4). Contrary to the above, on October 17, 2017, Exelon identified a discrepancy in PARAGON (risk software) that resulted in an improper risk assessment for the days planned work. Review and correction of the error resulted in an elevated risk condition of Yellow during Nine Mile Point Unit 1, 11 feedwater pump (FW) maintenance. This performance deficiency was determined to be more than minor because it adversely affected the human performance attribute of the Mitigating Systems cornerstone and affected cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, on October 17, 2017, Exelon identified a planned activity that resulted in an unplanned Yellow risk activity during planned maintenance of the 11 FW pump. In addition, IMC 0612, Appendix E, Examples of Minor Issues, under Section 7, Maintenance Rule, Example E for inadequate risk assessment states in part that a more-than-minor issue would put the plant into a higher licensee-established risk category. The finding was evaluated using IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process. The finding was determined to affect the overall plant risk with the 11 FW Pump being out of service for maintenance with PARAGON not elevating the overall plant risk from green to yellow. The risk deficit was elevated and determined to not be greater than 1E-6 event per year for Incremental Core Damage Probability Differential and not greater than 1E-7 events per year for Incremental Large Early Release Probability Differential. Therefore, the finding was determined to be of very low safety significance (Green). Exelon entered this issue into its CAP as IR 04064241. | Feedwater |
| 05000353/FIN-2017004-01 | 31 December 2017 23:59:59 | Limerick | Unplanned HPCI Inoperability Due to Isolating All Suction Sources During Post-Maintenance Te s t i n g | The inspectors identified a self-revealing Green non-cited violation (NCV) of 10 Code of Federal Regulations (CFR) 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for Exelons failure to adequately establish post-maintenance testing instructions for a relay replacement for the Unit 2 high pressure coolant injection (HPCI) system. Specifically, implementing the instructions caused a loss of all suction sources and unplanned inoperability of the Unit 2 HPCI system. Exelon initiated a condition report (issue report (IR) 4036417) and conducted a technical human performance (THU) workshop with the maintenance planning department to increase awareness of THU tools and added THU behavior discussion topics to weekly maintenance planning department all hands meetings.This finding is more than minor because it adversely affected the configuration control attribute of the mitigating systems cornerstone to ensure the availability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, HPCI was made inoperable when it was planned to remain operable. Using IMC 0609, Appendix A, Exhibit 2, the inspectors determined that this finding required a detailed risk assessment because it represented a loss of the single train systems function. The Regional Senior Reactor Analyst performed a detailed risk evaluation using the Limerick Generating Station (LGS) Unit 2 Standardized Plant Analysis Risk Model. The issue was modeled with a HPCI failure to start due to the suction valves being closed. The change in core damage frequency per year was determined to be in the low E-9 range due to the very short duration that both suction sources were isolated. Therefore the issue was determined to be of very low safety significance (Green). The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Work Management, because the work process did not ensure individuals were aware of plant status and the changes in the plan of work were not effectively implemented. (H.5) | High Pressure Coolant Injection |